U.S. patent number 6,767,867 [Application Number 10/122,671] was granted by the patent office on 2004-07-27 for methods of treating subterranean zones penetrated by well bores.
This patent grant is currently assigned to Halliburton Energy Services, Inc.. Invention is credited to D. Chad Brenneis, Jiten Chatterji, Shih-Ruey T. Chen, Roger S. Cromwell, Ronald J. Crook, Valentino L. DeVito, Kevin W. Frederick, Dennis W. Gray, Bobby J. King, Randy J. Loeffler, Kevin W. Smith.
United States Patent |
6,767,867 |
Chatterji , et al. |
July 27, 2004 |
Methods of treating subterranean zones penetrated by well bores
Abstract
The present invention provides methods of treating subterranean
zones penetrated by well bores in primary well cementing
operations, well completion operations, production stimulation
treatments and the like. The methods are basically comprised of
introducing into the subterranean zone an aqueous well treating
fluid comprised of water and a water soluble polymer complex fluid
loss control additive.
Inventors: |
Chatterji; Jiten (Duncan,
OK), Cromwell; Roger S. (Walters, OK), King; Bobby J.
(Duncan, OK), Brenneis; D. Chad (Marlow, OK), Gray;
Dennis W. (Comanche, OK), Crook; Ronald J. (Duncan,
OK), Chen; Shih-Ruey T. (Pittsburgh, PA), DeVito;
Valentino L. (Pittsburgh, PA), Frederick; Kevin W.
(Evans City, PA), Smith; Kevin W. (McMurray, PA),
Loeffler; Randy J. (Carnegie, PA) |
Assignee: |
Halliburton Energy Services,
Inc. (Duncan, OK)
|
Family
ID: |
23088643 |
Appl.
No.: |
10/122,671 |
Filed: |
April 15, 2002 |
Current U.S.
Class: |
507/216; 166/295;
507/211; 507/921; 507/902; 507/229; 507/226; 507/225; 507/214;
507/209 |
Current CPC
Class: |
A61K
8/8158 (20130101); A61K 8/8182 (20130101); A61Q
5/02 (20130101); A61Q 19/00 (20130101); C02F
1/78 (20130101); C02F 11/14 (20130101); C04B
24/163 (20130101); C04B 24/168 (20130101); C04B
24/38 (20130101); C04B 28/02 (20130101); C04B
28/04 (20130101); C04B 40/0039 (20130101); C08B
11/20 (20130101); C08B 15/00 (20130101); C08F
251/00 (20130101); C08F 291/00 (20130101); C08L
1/284 (20130101); C08L 33/14 (20130101); C09K
8/12 (20130101); C09K 8/44 (20130101); C09K
8/46 (20130101); C09K 8/473 (20130101); C09K
8/508 (20130101); C09K 8/5083 (20130101); C09K
8/512 (20130101); C09K 8/514 (20130101); C09K
8/518 (20130101); C09K 8/62 (20130101); C09K
8/685 (20130101); C09K 8/703 (20130101); C09K
8/706 (20130101); D21H 21/10 (20130101); D21H
21/56 (20130101); C04B 28/04 (20130101); C04B
24/163 (20130101); C04B 24/22 (20130101); C04B
24/38 (20130101); C04B 24/383 (20130101); C04B
38/10 (20130101); C04B 28/04 (20130101); C04B
24/168 (20130101); C04B 24/22 (20130101); C04B
24/383 (20130101); C04B 38/10 (20130101); C08L
1/284 (20130101); C08L 33/14 (20130101); C04B
28/02 (20130101); C04B 24/163 (20130101); C04B
24/383 (20130101); C04B 38/10 (20130101); C04B
40/0039 (20130101); C04B 40/0039 (20130101); C04B
24/2688 (20130101); C04B 24/38 (20130101); C04B
40/0039 (20130101); C04B 24/2641 (20130101); C04B
24/383 (20130101); C04B 40/0039 (20130101); C04B
24/2652 (20130101); C04B 24/383 (20130101); C04B
40/0039 (20130101); C04B 24/163 (20130101); C04B
24/383 (20130101); A61K 2800/54 (20130101); A61K
2800/56 (20130101); C04B 2111/70 (20130101); C08L
1/02 (20130101); D21H 17/375 (20130101); Y10S
507/921 (20130101); Y10S 507/902 (20130101); Y10S
524/922 (20130101); C04B 2103/46 (20130101); C08L
2666/02 (20130101); C08L 2666/26 (20130101); C04B
2103/0046 (20130101); C04B 2103/0053 (20130101) |
Current International
Class: |
C09K
8/70 (20060101); C09K 8/12 (20060101); C08F
291/00 (20060101); C09K 8/62 (20060101); C04B
24/16 (20060101); C09K 8/50 (20060101); C09K
8/44 (20060101); C09K 8/02 (20060101); C09K
8/46 (20060101); C09K 8/60 (20060101); C04B
28/00 (20060101); D21H 21/00 (20060101); D21H
21/56 (20060101); C04B 28/04 (20060101); C08F
251/00 (20060101); C04B 24/38 (20060101); C02F
1/78 (20060101); C08L 33/00 (20060101); C04B
24/00 (20060101); C08L 33/14 (20060101); C02F
11/14 (20060101); C09K 8/512 (20060101); C09K
8/514 (20060101); C09K 8/42 (20060101); C09K
8/518 (20060101); C09K 8/508 (20060101); C08L
1/02 (20060101); C08L 1/00 (20060101); C09K
003/00 (); E21B 033/13 () |
Field of
Search: |
;507/209,211,214,216,225,226,229,902,921 ;166/295,285 ;175/72 |
References Cited
[Referenced By]
U.S. Patent Documents
Foreign Patent Documents
Primary Examiner: Tucker; Philip C.
Attorney, Agent or Firm: Dougherty, Jr.; C. Clark
Parent Case Text
CROSS-REFERENCES TO RELATED APPLICATIONS
This application claims the benefit of Provisional Application No.
60/284,043 entitled "Water Soluble Polymer Complexes" filed on Apr.
16, 2001.
Claims
What is claimed is:
1. A method of treating a subterranean zone penetrated by a well
bore comprising introducing into the subterranean zone an aqueous
well treating fluid comprising water and a water soluble polymer
complex fluid loss control additive that comprises 1 part by weight
of a cationic, anionic or amphoteric polymer comprising 40 mole %
of 2-acrylamido-2-methyl propane sulfonic acid, 30 mole % of
acrylamide, 20 mole % of acrylic acid and 10 mole % of vinyl
pyrrolidone and 1 part by weight of a nonionic host polymer
comprising hydroxyethylcellulose having 1.5 moles of ethylene oxide
substitution and wherein said cationic, anionic or amphoteric
polymer is formed in the presence of said nonionic host
polymer.
2. A method of treating a subterranean zone penetrated by a well
bore comprising introducing into the subterranean zone an aqueous
well treating fluid comprising water, a water soluble polymer
complex fluid loss control additive that comprises a cationic,
anionic or amphoteric polymer formed in the presence of a nonionic
host polymer, a hydraulic cement, a gas in an amount sufficient to
foam said aqueous well treating fluid, and a mixture of foaming and
foam stabilizing surfactants, present in an effective amount, and
comprising an ethoxylated alcohol ether sulfate surfactant, an
alkyl or alkene amidopropyl betaine surfactant and an alkyl or
alkene amidopropyl dimethyl amine oxide surfactant.
3. A method of treating a subterranean zone penetrated by a well
bore comprising introducing into the subterranean zone an aqueous
well treating fluid comprising water, a water soluble polymer
complex fluid loss control additive that comprises a cationic,
anionic or amphoteric polymer formed in the presence of a nonionic
host polymer, a gelling agent for increasing the viscosity of said
well treating fluid, and a cross-linking agent for cross-linking
said gelling agent.
4. The method of claim 3 wherein said cross-linking agent is
selected from the group consisting of borate releasing compounds, a
source of titanium ions, a source of zirconium ions, a source of
antimony ions and a source of aluminum ions.
5. The method of claim 3 wherein said cross-linking agent is
present in said aqueous well treating fluid in an amount in the
range of from about 0.1% to about 2% by weight of said gelling
agent in said treating fluid.
6. The method of claim 3 wherein said aqueous well treating fluid
further comprises a delayed breaker present in an amount sufficient
to effect a reduction in the viscosity of said treating fluid after
said treating fluid has been in said subterranean zone for a period
of time.
7. The method of claim 6 wherein said delayed breaker is selected
from the group consisting of alkali metal and ammonium persulfates
which are delayed by being encapsulated in a material which slowly
releases said breaker or by a breaker selected from the group
consisting of alkali metal chlorites, alkali metal hypochlorites
and calcium hypochlorites.
8. A method of cementing a subterranean zone penetrated by a well
bore comprising introducing into the subterranean zone a cement
composition comprising a hydraulic cement slurried with water and a
water soluble polymer complex fluid loss control additive that
comprises a cationic, anionic or amphoteric polymer formed in the
presence of a nonionic host polymer, wherein said nonionic polymer
is hydroxyethylcellulose having 1.5 moles of ethylene oxide
substitution, said polymer complex fluid loss control additive
being present in an amount in the range of from about 0.25% to
about 5% by weight of cement in said composition.
9. A method of cementing a subterranean zone penetrated by a well
bore comprising introducing into the subterranean zone a cement
composition comprising a hydraulic cement slurried with water and a
water soluble polymer complex fluid loss control additive that
comprises a cationic, anionic or amphoteric polymer formed in the
presence of a nonionic host polymer, wherein the monomer units
forming said polymer comprise 2-acrylamido-2-methyl propane
sulfonic acid monomer units present in said polymer in an amount in
the range of from about 25 mole % to about 75 mole % and
N,N-dimethylacrylamide monomer units present in said polymer in an
amount in the range of from about 10 mole % to about 40 mole %,
said polymer complex fluid loss control additive being present in
an amount in the range of from about 0.25% to about 5% by weight of
cement in said composition.
10. A method of cementing a subterranean zone penetrated by a well
bore comprising introducing into the subterranean zone a cement
composition comprising a hydraulic cement slurried with water and a
water soluble polymer complex fluid loss control additive that
comprises a cationic, anionic or amphoteric polymer formed in the
presence of a nonionic host polymer, wherein the monomer units
forming said polymer comprise 2-acrylamido-2-methyl propane
sulfonic acid monomer units present in said polymer in an amount in
the range of from about 25 mole % to about 75 mole % and vinyl
pyrrolidone monomer units present in said polymer in an amount in
the range of from about 5 mole % to about 20 mole %, said polymer
complex fluid loss control additive being present in an amount in
the range of from about 0.25% to about 5% by weight of cement in
said composition.
11. A method of cementing a subterranean zone penetrated by a well
bore comprising introducing into the subterranean zone a cement
composition comprising a hydraulic cement slurried with water and a
water soluble polymer complex fluid loss control additive that
comprises 1 part by weight of a polymer comprising 70 mole % of
2-acrylamido-2-methyl propane sulfonic acid, 17 mole % of
N,N-dimethylacrylamide and 13 mole % of acrylamide and 2 parts by
weight of a nonionic host polymer comprising hydroxyethylcellulose
having 1.5 moles of ethylene oxide substitution, wherein said
polymer is formed in the presence of said nonionic host polymer,
said polymer complex fluid loss control additive being present in
an amount in the range of from about 0.25% to about 5% by weight of
cement in said composition.
12. A method of cementing a subterranean zone penetrated by a well
bore comprising introducing into the subterranean zone a cement
composition comprising a hydraulic cement slurried with water and a
water soluble polymer complex fluid loss control additive that
comprises 1 part by weight of a polymer comprising 40 mole % of
2-acrylamido-2-methyl propane sulfonic acid, 30 mole % of
acrylamide, 20 mole % of acrylic acid, and 10 mole % of vinyl
pyrrolidone and 1 part by weight of a nonionic host polymer
comprising hydroxyethylcellulose having 1.5 moles of ethylene oxide
substitution, wherein said polymer is formed in the presence of
said nonionic host polymer, said polymer complex fluid loss control
additive being present in an amount in the range of from about
0.25% to about 5% by weight of cement in said composition.
13. A method of cementing a subterranean zone penetrated by a well
bore comprising introducing into the subterranean zone a cement
composition comprising a hydraulic cement slurried with water, a
water soluble polymer complex fluid loss control additive that
comprises a cationic, anionic or amphoteric polymer formed in the
presence of a nonionic host polymer and present in an amount in the
range of from about 0.25% to about 5% by weight of cement in said
composition, a gas in an amount sufficient to foam said cement
composition and a mixture of foaming and foam stabilizing
surfactants present in an effective amount and comprising an
ethoxylated alcohol ether sulfate surfactant, an alkyl or alkene
amidopropyl betaine surfactant and an alkyl or alkene amidopropyl
dimethyl amine oxide surfactant.
14. A method of treating a subterranean zone penetrated by a well
bore comprising introducing into said subterranean zone an aqueous
well treating fluid comprising water, a gelling agent present in an
amount in the range of from about 0.125% to about 1.5% by weight of
water in said aqueous well treating fluid, and a water soluble
polymer complex fluid loss control additive that comprises 1 part
by weight of a polymer comprising 70 mole % of
2-acrylamido-2-methyl propane sulfonic acid, 17 mole % of
N,N-dimethylacrylamide and 13 mole % of acrylamide and 2 parts by
weight of a nonionic host polymer comprising hydroxyethylcellulose
having 1.5 moles of ethylene oxide substitution, wherein said
polymer is formed in the presence of said nonionic host polymer,
said polymer complex fluid loss control additive being present in
an amount in the range of from about 0.1% to about 5% by weight of
water in said aqueous well treating fluid.
15. A method of treating a subterranean zone penetrated by a well
bore comprising introducing into said subterranean zone an aqueous
well treating fluid comprising water, a gelling agent present in an
amount in the range of from about 0.125% to about 1.5% by weight of
water in said aqueous well treating fluid, and a water soluble
polymer complex fluid loss control additive comprising 40 mole % of
2-acrylamido-2-methyl propane sulfonic acid, 30 mole % of
acrylamide, 20 mole % of acrylic acid and 10 mole % of vinyl
pyrrolidone and 1 part by weight of a nonionic host polymer
comprising hydroxyethylcellulose having 1.5 moles of ethylene oxide
substitution, wherein said polymer is formed in the presence of
said nonionic host polymer, said polymer complex fluid loss control
additive being present in an amount in the range of from about 0.1%
to about 5% by weight of water in said aqueous well treating
fluid.
16. A method of treating a subterranean zone penetrated by a well
bore comprising introducing into said subterranean zone an aqueous
well treating fluid comprising water, a gelling agent present in an
amount in the range of from about 0.125% to about 1.5% by weight of
water in said aqueous well treating fluid, a water soluble polymer
complex fluid loss control additive that comprises a cationic,
anionic or amphoteric polymer formed in the presence of a nonionic
host polymer and is present in an amount in the range of from about
0.1% to about 5% by weight of water in said aqueous well treating
fluid, and a cross-linking agent for cross-linking said gelling
agent.
17. The method of claim 16 wherein said cross-linking agent is
selected from the group consisting of borate releasing compounds, a
source of titanium ions, a source of zirconium ions, a source of
antimony ions and a source of aluminum ions.
18. The method of claim 16 wherein said cross-linking agent is
present in said aqueous well treating fluid in an amount in the
range of from about 0.1% to about 2% by weight of said gelling
agent in said treating fluid.
19. The method of claim 16 wherein said aqueous well treating fluid
further comprises a delayed breaker present in an amount sufficient
to effect a reduction in the viscosity of said treating fluid after
said treating fluid has been in said subterranean zone for a period
of time.
20. The method of claim 19 wherein said delayed breaker is selected
from the group consisting of alkali metal and ammonium persulfates
which are delayed by being encapsulated in a material which slowly
releases said breaker or by a breaker selected from the group
consisting of alkali metal chlorites, alkali metal hypochlorites
and calcium hypochlorites.
21. A method of treating a subterranean zone penetrated by a well
bore comprising introducing into the subterranean zone an aqueous
well treating fluid comprising water, a water soluble polymer
complex fluid loss control additive that comprises a cationic,
anionic or amphoteric polymer formed in the presence of a nonionic
host polymer, a gelling agent for increasing the viscosity of said
fluid, and a delayed breaker present in an amount sufficient to
effect a reduction in the viscosity of said treating fluid after
said treating fluid has been in said subterranean zone for a period
of time.
22. The method of claim 21 wherein said delayed breaker is selected
from the group consisting of alkali metal and ammonium persulfates
which are delayed by being encapsulated in a material which slowly
releases said breaker or by a breaker selected from the group
consisting of alkali metal chlorites, alkali metal hypochlorites
and calcium hypochlorites.
23. A method of treating a subterranean zone penetrated by a well
bore comprising introducing into said subterranean zone an aqueous
well treating fluid comprising water, a gelling agent present in an
amount in the range of from about 0.125% to about 1.5% by weight of
water in said aqueous well treating fluid, and a water soluble
polymer complex fluid loss control additive that comprises a
cationic, anionic or amphoteric polymer formed in the presence of a
nonionic host polymer and present in an amount in the range of from
about 0.1% to about 5% by weight of water in said aqueous well
treating fluid, and a delayed breaker present in an amount
sufficient to effect a reduction in the viscosity of said treating
fluid after said treating fluid has been in said subterranean zone
for a period of time.
24. The method of claim 23 wherein said delayed breaker is selected
from the group consisting of alkali metal and ammonium persulfates
which are delayed by being encapsulated in a material which slowly
releases said breaker or by a breaker selected from the group
consisting of alkali metal chlorites, alkali metal hypochlorites
and calcium hypochlorites.
Description
BACKGROUND OF THE INVENTION
1. Field of the Invention
The present invention relates to methods of treating subterranean
zones penetrated by well bores with aqueous treating fluids
comprised of water and a water soluble fluid loss additive
comprised of a polymer complex.
2. Description of the Prior Art
Well treating fluids are used in a variety of operations and
treatments in oil and gas wells. Such operations and treatments
include well completion operations such as gravel packing to
prevent formation solids from being carried out of the well bore
with produced hydrocarbon fluids. In gravel packing, suspended
gravel particles are carried into a subterranean zone containing a
screen in which a gravel pack is to be placed by a viscous gelled
treating fluid. Once the gravel pack is placed in the zone, the
viscous gelled fluid is broken (the viscosity is reduced) and
recovered (returned to the surface). In order to prevent the loss
of fluid components of the treating fluid into permeable formations
penetrated by the well bore, a fluid loss control additive is
included in the treating fluid. The gravel pack formed in the well
bore functions as a filter to separate formation solids from
produced fluids while permitting the produced fluids to flow into
and through the well bore.
Aqueous well treating fluids containing hydraulic cement are
utilized extensively in the construction and repair of oil and gas
wells. For example, hydraulic cement compositions are used in
primary well cementing operations which involve the placement of a
cement composition into the annular space between the walls of a
well bore and the exterior surfaces of a pipe string such as casing
disposed therein. The cement composition is permitted to set in the
annular space thereby forming an annular sheath of hardened
impermeable cement therein. The objective of the cement sheath is
to physically support and position the pipe string in the well bore
and bond the pipe string to the walls of the well bore whereby the
undesirable migration of formation fluids between subterranean
zones penetrated by the well bore is prevented.
An example of a production stimulation treatment utilizing a well
treating fluid is hydraulic fracturing. That is, a viscous gelled
aqueous treating fluid, referred to in the art as a fracturing
fluid, is pumped through the well bore into a subterranean zone to
be stimulated at a rate and pressure such that fractures are formed
and extended into the subterranean zone. The fracturing fluid also
carries particulate proppant material, e.g., sand, into the
fractures. The proppant material is suspended in the viscous
fracturing fluid so that the proppant material is deposited in the
fractures when the viscous fracturing fluid is broken and
recovered. The proppant material functions to prevent the formed
fractures from closing whereby conductive channels are formed
through which production fluids can flow to the well bore. In order
to prevent the loss of the fracturing fluid to permeable
subterranean formations, a water soluble fluid loss control
additive is included in the fracturing fluid. After the viscous
fracturing fluid has been pumped into a subterranean zone in a
formation and fracturing of the zone has taken place, the
fracturing fluid is removed from the formation to allow produced
hydrocarbons to flow through the created fractures. Generally, the
removal of the viscous fracturing fluid is accomplished by
converting the fracturing fluid into a low viscosity fluid. This is
accomplished by adding a delayed breaker, i.e., a viscosity
reducing additive, to the fracturing fluid prior to pumping it into
the subterranean zone to be fractured.
The success of gravel packing operations, primary cementing
operations, fracturing operations and other operations utilizing
aqueous well treating fluids depend, at least in part, on the
ability of the treating fluid used to retain water until it has
been placed in a desired well location. That is, as an aqueous
treating fluid is pumped through the well bore and contacts
permeable subterranean formations penetrated thereby, water
included in the treating fluid can be lost to the permeable
formations. The loss of water from the treating fluid can prevent
the treating fluid from functioning in the manner intended. For
example, when portions of the water forming a cement composition
are lost, the consistency of the cement composition is also lost
which can prevent the composition from being placed in the intended
location, the composition can become too viscous for placement
and/or the composition fractures subterranean formations whereby
all or part of the composition is lost. While lightweight foamed
aqueous treating fluids such as foamed cement compositions are
often utilized, such foamed treating fluids are also subject to
fluid loss when in contact with permeable surfaces.
Heretofore, a variety of fluid loss reducing additives have been
developed and used in aqueous well treating fluids. Such additives
reduce the loss of liquids, usually water, from such treating
fluids when the treating fluids are in contact with permeable
surfaces. While the heretofore utilized fluid loss control
additives have achieved varying degrees of success, there is a
continuing need for improved fluid loss control additives which can
be utilized in non-foamed and foamed aqueous well treating fluids
and which effectively reduce fluid loss from the aqueous well
treating fluids at high temperatures.
SUMMARY OF THE INVENTION
The present invention provides improved methods of treating
subterranean zones penetrated by well bores with aqueous well
treating fluids having improved low fluid loss properties which
meet the needs described above and overcome the shortcomings of the
prior art.
The improved methods of this invention for treating a subterranean
zone penetrated by a well bore comprise introducing into the
subterranean zone an aqueous well treating fluid comprised of water
and a water soluble polymer complex fluid loss control additive.
The fluid loss control additive is comprised of a polymer complex
of two or more water-soluble polymers. That is, the fluid loss
control additives utilized in accordance with this invention are
polymer complexes comprised of a cationic, anionic or amphoteric
polymer formed in the presence of a nonionic polymer. The polymer
complexes are comprised of polymers which are not physically
blended, but which are intimately intermixed or interjacent because
of the way they are produced. The fluid loss control additive
polymer complexes are produced by forming one of the polymeric
components in the presence of another polymeric component which is
already in place in the polymerization zone. Thus, a solution,
emulsion or other preparation of the monomers desired to be
incorporated in the formed polymer is prepared with the desired
initiator or catalyst and a polymer is formed (synthesized) in the
presence of a previously prepared or natural polymer, which is
herein referred to as the host polymer. Because the host polymer is
present throughout the polymerization mix, the newly formed polymer
is interjacent with the host polymer. Since both the polymers of
the polymer complex formed are water soluble, the polymer complex
is water soluble.
The nonionic polymer, i.e., the host polymer, in the fluid loss
control additive utilized in accordance with the present invention
is preferably a natural polymer. More preferably, the nonionic
polymer is a hydroxyalkylated natural gum, and most preferably, the
nonionic polymer is ethoxylated hydroxyethylcellulose. The
cationic, anionic or amphoteric polymer which is polymerized in the
presence of the nonionic polymer is preferably comprised, at least
in part, of monomer units derived from a sulfonic acid functional
monomer. Most preferably, the polymer is comprised of 2-acrylamido-
2-methyl propane sulfonic acid monomer units which are present in
the polymer in an amount in the range of from about 25 mole % to
about 75 mole %. The polymer can include other monomer units such
as N,N-dimethylacrylamide, acrylamide, acrylic acid and
vinylpyrrolidone.
A preferred method of this invention for treating a subterranean
zone penetrated by a well bore comprises introducing into the
subterranean zone an aqueous well treating fluid comprised of water
and a water soluble polymer complex fluid loss control additive
comprised of 1 part by weight of a polymer comprising 70 mole % of
2-acrylamido-2-methyl propane sulfonic acid, 17 mole % of
N,N-dimethylacrylamide and 13 mole % of acrylamide, and 2 parts by
weight hydroxyethylcellulose having 1.5 moles of ethylene oxide
substitution.
Another preferred water soluble polymer complex fluid loss control
additive for use in accordance with the methods of this invention
is comprised of 1 part by weight of a polymer comprising 40 mole %
of 2-acrylamido-2-methyl propane sulfonic acid, 30 mole % of
acrylamide, 20 mole % of acrylic acid and 10 mole % of
vinylpyrrolidone, and 1 part by weight of hydroxyethylcellulose
having 1.5 moles of ethylene oxide substitution.
The aqueous well treating fluid can be a foamed or non-foamed
hydraulic cement composition, a viscous gravel pack forming fluid,
a fracturing fluid or other aqueous well treating fluid.
The objects, features and advantages of this invention will be
readily apparent to those skilled in the art upon a reading of the
description of preferred embodiments which follows.
DESCRIPTION OF PREFERRED EMBODIMENTS
The present invention provides improved methods of treating
subterranean zones penetrated by well bores utilizing treating
fluids containing water soluble polymer complex fluid loss control
additives. That is, the treating fluids are basically comprised of
water and a polymer complex fluid loss control additive and may
include hydraulic cement, viscosity increasing gelling agents,
cross-linkers for the gelling agents, viscosity breakers and other
components known to those skilled in the art. Thus, the treating
fluids useful in accordance with the methods of this invention can
be compositions basically comprised of water and the polymer
complex fluid loss control additive, hydraulic cement compositions,
gravel pack forming compositions, fracturing fluids and the like.
When the treating fluid is comprised of water and the fluid loss
control additive, the fluid loss control additive is present in an
amount in the range of from about 0.09% to about 2.5% by weight of
the water.
The water soluble polymer complex fluid loss control additives
useful in accordance with this invention are comprised of a complex
of two water soluble polymers. The polymer complexes are prepared
by polymerizing one or more polymerizable monomers in the presence
of a previously formed or natural polymer. The polymer complexes
are intercalated as a result of the way they are produced. That is,
the complexes are prepared by polymerizing monomer components in
the presence of a previously formed or natural polymer which is
included in the polymerization mixture. A solution, emulsion or
other preparation of the monomers to be polymerized is prepared
with the desired initiator or catalyst and a polymer is synthesized
in the presence of the previously formed or natural polymer, i.e.,
the host polymer. Because the host polymer is present throughout
the polymerization mixture, the host polymer is intercalated with
the new polymer being formed. Both of the polymers are water
soluble which makes the polymer complex water soluble. In oil and
gas well completion and production stimulation applications, the
polymer complex fluid loss control additives are formed by
polymerizing a cationic, anionic or amphoteric polymer in the
presence of a nonionic host polymer. Thus, the term "polymer
complex fluid loss control additive" is used herein to mean a
cationic, anionic or amphoteric polymer which is polymerized in the
presence of a nonionic host polymer.
As mentioned above, the polymer complex fluid loss control
additives are particularly suitable for use in treating fluids
which are basically comprised of water and other components such as
hydraulic cement, viscosity increasing gelling agents or the like.
Stated another way, the polymer complex fluid loss control
additives are particularly suitable for use in aqueous well
treating fluids such as foamed or nonfoamed hydraulic cement
compositions, viscous aqueous fracturing fluids and other aqueous
well treating fluids utilized in the drilling, completion and
stimulation of oil and gas wells.
The polymer complex fluid loss control additives useful in
accordance with this invention are particularly suitable for use in
foamed or nonfoamed hydraulic cement compositions which are
utilized for cementing well bores at high temperatures, i.e.,
temperatures in the range of from about 80.degree. F. to the bottom
hole circulation temperature (BHCT), i.e., about 350.degree. F. The
polymer complexes provide fluid loss control over a wide range of
temperature and other well conditions.
As mentioned, the polymer complexes of the present invention are
formed by polymerizing one or more monomers in the presence of a
host polymer. The host polymer can be a synthetic polymer such as
those produced by free radical polymerization or condensation
polymerization or it may be a natural polymer such as a natural
gum, a starch, a modified starch, a cellulosic material or a
modified cellulosic material. Examples of host polymers that can be
utilized in the polymer complex include, but are not limited to,
vinyl polymers, polyolefins, polyacrylates, polyamides, polyesters,
polyurethanes, xanthan gums, sodium alginates, galactomannans,
carragenan, gum arabic, cellulose and its derivatives, starch and
its derivatives, guar and its derivatives, silicone containing
polymers and their derivatives, polysiloxanes and their derivatives
and proteins and their derivatives.
The host polymer is preferably a nonionic polymer such as a water
soluble natural gum. While various natural gums can be used of the
types described above, a hydroxyalkylated natural gum such as
hydroxyethyl guar gum or hydroxypropyl guar gum.
The cationic, anionic or amphoteric polymer formed in the presence
of the nonionic host polymer can include monomer units derived from
one or more monomers. Preferably, a majority of the monomer units
for forming the polymer are monomer units derived from a sulfonic
acid functional monomer. Of the various sulfonic acid functional
monomers that can be used, 2-acrylamido-2-methyl propane sulfonic
acid monomer units present in the polymer in an amount in the range
of from about 25 mole % to about 75 mole % are preferred. One or
more additional monomer units can be included in the formed polymer
in addition to the sulfonic acid functional monomer units.
Preferred such additional monomer units are N,N-dimethylacrylamide
monomer units present in the polymer in an amount in the range of
from about 10 mole % to about 40 mole %, acrylamide monomer units
present in the polymer in an amount in the range of from about 10
mole % to about 30 mole %, acrylic acid monomer units present in
the polymer in an amount in the range of from about 10 mole % to
about 20 mole % and/or vinylpyrrolidone monomer units present in
the polymer in an amount in the range of from about 5 mole % to
about 20 mole %.
A particularly suitable water soluble polymer complex fluid loss
control additive for use in accordance with this invention is
comprised of 1 part by weight of a polymer comprised of about 70
mole % of 2-acrylamido-2-methyl propane sulfonic acid, about 17
mole % of N,N-dimethylacrylamide and about 13 mole % of acrylamide,
and 2 parts by weight of hydroxyethylcellulose having 1.5 moles of
ethylene oxide substitution.
Another particularly preferred water soluble polymer complex fluid
loss control additive for use in accordance with this invention is
comprised of 1 part by weight of a polymer comprised of about 40
mole % of 2-acrylamido-2-methyl propane sulfonic acid, about 30
mole % of acrylamide, about 20 mole % of acrylic acid and about 10
mole % of vinyl pyrrolidone, and 1 part by weight of
hydroxyethylcellulose having 1.5 moles of ethylene oxide
substitution.
A method of this invention for cementing a subterranean zone
penetrated by a well bore comprises introducing into the
subterranean zone a cement composition comprised of a hydraulic
cement slurried with water present in an amount in the range of
from about 35% to about 50% by weight of cement in the composition
and a water soluble polymer complex fluid loss control additive
present in an amount in the range of from about 0.25% to about 5%
by weight of cement in the composition.
Another method of this invention for cementing a subterranean zone
penetrated by a well bore comprises introducing into the
subterranean zone a cement composition comprised of a hydraulic
cement slurried with water present in an amount in the range of
from about 35% to about 50% by weight of cement in the composition,
a water soluble polymer complex fluid loss control additive present
in an amount in the range of from about 0.25% to about 5% by weight
of cement in the composition, a gas present in an amount sufficient
to foam the aqueous well treating fluid and a mixture of foaming
and foam stabilizing surfactants present in an effective
amount.
A variety of hydraulic cements can be utilized in accordance with
the present invention including those comprised of calcium,
aluminum, silicon, oxygen and/or sulfur which set and harden by
reaction with water. Such hydraulic cements include, but are not
limited to, Portland cements, pozzolana cements, gypsum cements,
aluminous cements, silica cements, and slag cements. Portland
cements are generally preferred for use in accordance with this
invention. Portland cements of the types defined and described in
API Specification For Materials And Testing For Well Cements, API
Specification 10, 5.sup.th Edition, dated Jul. 1, 1990 of the
American Petroleum Institute are particularly suitable. Preferred
such API Portland cements include classes A, B, C, G and H, with
API classes G and H being more preferred and class H being the most
preferred.
The water utilized in a cement composition of this invention is
present in a quantity sufficient to produce a pumpable slurry of
desired density. The water can be fresh water or salt water. The
term "salt water" is used herein to mean unsaturated salt solutions
and saturated salt solutions including brines and seawater. The
water is generally present in the cement compositions in an amount
in the range of from about 35% to about 50% by weight of the cement
in the composition.
As mentioned above, the polymer complex fluid loss control additive
is preferably formed of a cationic, anionic or amphoteric polymer
in the presence of a host nonionic polymer. Such polymer complexes
provide excellent fluid loss control in both nonfoamed and foamed
cement compositions over a wide range of temperature and well
conditions. When the polymer complex includes a formed polymer or a
host polymer of one or more acrylamide type monomers and/or a basic
vinylheterocyclic monomer such as vinylimidazole, vinylpyridine,
vinylpyrrolidone and their derivatives, the cementing composition
may optionally include a dispersant such as naphthalene sulfonic
acid condensed with formaldehyde or the condensation reaction
product of acetone, formaldehyde and sodium bisulfite. The
inclusion of a dispersant has a synergistic affect on the polymer
complex which results in an unexpected increase in its
effectiveness as a fluid loss control additive.
When included, the dispersant is present in an amount in the range
of from about 0.5% to a maximum about 2% by weight of cement. A
dispersant can not be used in foamed cement.
The various additives conventionally included in cement
compositions which are well known to those skilled in the art can
also be utilized in the cement compositions of this invention in
amounts known to those skilled in the art.
The polymer complex fluid loss control additives of this invention,
when used in a cement composition, effect a substantial reduction
in the rate of water loss from the cement composition as well as in
the apparent viscosity of the cement composition. The polymer
complex is easily mixed with the other components of the cement
composition and results in good fluid loss control over a wide
temperature range without affecting rheology adversely. The polymer
complex can be added to a cement composition in dry, solution or
emulsion form. The presence of the polymer complex fluid loss
control additive in a cement composition also improves the
pumpability of the cement composition.
As mentioned above, the polymer complex fluid loss control additive
included in a cement composition of this invention is preferably
selected from the group of a polymer complex comprised of 1 part by
weight of a polymer comprising 70 mole % of 2-acrylamido-2-methyl
propane sulfonic acid, 17 mole % of N,N-dimethylacrylamide and 13
mole % of acrylamide, and 2 parts by weight of
hydroxyethylcellulose containing 1.5 moles of ethylene oxide
substitution; or a polymer complex comprised of 1 part by weight of
a polymer comprising 40 mole % of 2-acrylamido-2-methyl propane
sulfonic acid, 30 mole % of acrylamide, 20 mole % of acrylic acid
and 10 mole % of vinylpyrrolidone, and 1 part by weight of
hydroxyethylcellulose having 1.5 moles of ethylene oxide
substitution.
The polymer complex fluid loss control additive utilized is
included in the cement composition in an amount in the range of
from about 0.25% to about 5% by weight of cement in the cement
composition.
When the cement composition is foamed, a gas in an amount
sufficient to foam the cement composition and a mixture of foaming
and foam stabilizing surfactants present in an effective amount are
included in the cement composition. The gas utilized for forming
the foamed cement composition can be air or nitrogen, with nitrogen
being preferred.
The gas is generally present in the cement composition in an amount
in the range of from about 10% to about 80% by volume of the final
foamed cement composition.
While various mixtures of foaming and foam stabilizing surfactants
can be utilized, a particularly suitable and preferred such mixture
is comprised of an ethoxylated alcohol ether sulfate surfactant, an
alkyl or alkene amidopropyl betaine surfactant and an alkyl or
alkene amidopropyldimethylamine oxide surfactant. This surfactant
mixture is described in detail in U.S. Pat. No. 6,063,738 issued to
Chatterji et al. on May 16, 2000, the disclosure of which is
incorporated herein by reference thereto.
The mixture of foaming and foam stabilizing surfactants is present
in the cement composition in an effective amount, i.e., in an
amount in the range of from about 0.8% to about 5% by volume of
water in the cement composition.
Another aqueous well treating fluid which can be utilized in
accordance with the methods of this invention is comprised of
water, a gelling agent present in an amount in the range of from
about 0.125% to about 1.5% by weight of water in the aqueous well
treating fluid and a water soluble polymer complex fluid loss
control additive present in an amount in the range of from about
0.1% to about 5% by weight of water in the aqueous well treating
fluid.
The water utilized in the well treating fluid can be fresh water or
salt water as described above.
One or more gelling agents for increasing the viscosity of the
aqueous treating fluid are included therein. The increased
viscosity of the treating fluid allows the treating fluid to carry
particulate solid materials and deposit the particulate solid
materials in a desired location. For example, when the viscous
gelled aqueous treating fluid is utilized as a fracturing fluid, it
is pumped into a subterranean zone by way of the well bore at a
rate and pressure sufficient to fracture the subterranean zone. The
viscous fracturing fluid carries particulate proppant material such
as graded sand into the fractures. The proppant material is
suspended in the viscous fracturing fluid so that the proppant
material is deposited in the fractures when the viscous fracturing
fluid is broken (reverts to a thin fluid) and recovered. The
proppant material functions to prevent the fractures from closing
whereby conductive channels are formed through which produced
fluids can flow to the well bore.
A viscous gelled aqueous treating fluid is also utilized in gravel
packing. In gravel packing operations, solid gravel particles, such
as graded sand or the like, are carried into a subterranean zone
containing a screen within which a gravel pack is to be placed by
the viscous aqueous treating fluid. That is, the gravel is
suspended in the viscous aqueous treating fluid at the surface and
carried into a space between the screen and the walls of the well
bore penetrating the subterranean zone within which the gravel pack
is to be placed. Once the gravel is placed in the zone, the viscous
gelled fluid is broken (the viscosity is reduced) and recovered
(returned to the surface). The gravel pack functions as a filter to
separate formation solids from produced fluids while permitting the
produced fluids to flow into and through the well bore.
A variety of gelling agents can be utilized to increase the
viscosity of aqueous well treating fluids such as fracturing
fluids, gravel packing fluids and the like. The useful gelling
agents include natural and derivatized polysaccharides which are
soluble, dispersible or swellable in an aqueous liquid to yield
viscosity to the liquid. One group, for example, of polysaccharides
which are suitable for use in accordance with the present invention
includes, but is not limited to, galactomannan gums such as gum
arabic, gum ghatti, gum karaya, tamarind gum, tragacanth gum, guar
gum, locust bean gum, and the like. The gums can also be
characterized as having one or more functional groups such as
cis-hydroxyl, hydroxyl, carboxyl, sulfate, sulfonate, amino or
amide. Modified gums such as carboxyalkyl derivatives, e.g.,
carboxymethylguar and hydroxyalkyl derivatives, e.g.,
hydroxypropylguar can also be employed. Doubly derivatized gums
such as carboxymethylhydroxypropylguar can also be used.
Modified celluloses and derivatives thereof can also be employed in
accordance with the present invention. Examples of water-soluble
cellulose ethers which can be used include, but are not limited to,
carboxyethylcellulose, carboxymethylcellulose,
carboxymethylhydroxyethylcellulose, hydroxyethylcellulose,
methylhydroxypropylcellulose, methylcellulose, ethylcellulose,
ethylcarboxymethylcellulose, methylethylcellulose,
hydroxypropylmethylcellulose and the like. A particularly suitable
derivatized cellulose is hydroxyethylcellulose grafted with vinyl
phosphonic acid which is described in detail in U.S. Pat. No.
5,067,565 issued to Holtmyer et al. on Nov. 26, 1991, the
disclosure of which is incorporated herein by reference
thereto.
Of the galactomannans and derivative galactomannans, guar gum,
hydroxypropylguar, carboxymethylhydroxypropylguar,
hydroxyethylcellulose, carboxymethylhydroxyethylcellulose,
carboxymethylcellulose, hydroxyethylcellulose grafted with vinyl
phosphonic acid are preferred.
Various other gelling agents known to those skilled in the art
including biopolymers such as xanthan gum, welan gum and
succinoglycon can also be used. The gelling agent or agents
utilized are included in the aqueous well treating fluids of this
invention in an amount in the range of from about 0.125% to about
1.5% by weight of water in the treating fluid.
In order to further enhance the development of viscosity of the
aqueous well treating fluid containing the above polysaccharide
gelling agents, the gelling agents can be cross-linked by the
addition of a cross-linking agent to the aqueous treating fluid.
The cross-linking agent can comprise a borate releasing compound or
any of the well known transition metal ions which are capable of
creating a cross-linked structure with the particular gelling agent
utilized. Preferred cross-linking agents for use with the above
described gelling agents include, but are not limited to, borate
releasing compounds, a source of titanium ions, a source of
zirconium ions, a source of antimony ions and a source of aluminum
ions.
When used, a cross-linking agent of the above types is included in
the aqueous well treating fluid in an amount in the range of from
about 0.1% to about 2% by weight of gelling agent in the treating
fluid.
When the aqueous well treating fluid includes a gelling agent or a
cross-linked gelling agent, a delayed breaker for the gelling agent
or cross-linked gelling agent is included in the aqueous well
treating fluid. That is, the delayed breaker is included in the
aqueous treating fluid in an amount sufficient to effect a
controlled reduction in the viscosity of the aqueous treating fluid
after a desired period of time. Suitable delayed breakers which can
be utilized include alkali metal and ammonium persulfates which are
delayed by being encapsulated in a material which slowly releases
the breaker. Such a material is precipitated particulate silica
which is porous and remains dry and free flowing after absorbing an
aqueous solution of the breaker. Precipitated silica can absorb
chemical additive solutions in amounts up to about 400% by weight
of the precipitated silica. The delayed release of a liquid
chemical additive absorbed in a particulate porous precipitated
silica is by osmosis whereby the encapsulated liquid chemical
diffuses through the porous solid material as a result of it being
at a higher concentration within the porous material than its
concentration in the liquid fluid outside the porous material. In
order to further delay the release of a liquid chemical additive,
the porous precipitated silica can be coated with a slowly soluble
coating. Examples of suitable such slowly soluble materials which
can be used include, but are not limited to, EDPM rubber,
polyvinyldichloride (PVDC), nylon, waxes, polyurethanes,
cross-linked partially hydrolyzed acrylics and the like. A detailed
description of the encapsulating techniques described above is set
forth in U.S. Pat. No. 6,209,646 issued on Apr. 3, 2001 to Reddy et
al., the disclosure of which is incorporated herein by reference
thereto. Other delayed breakers which can be utilized include, but
are not limited to, alkali metal chlorides and hypochlorites and
calcium hypochlorites.
When used, a breaker of the above types is included in the aqueous
well treating fluid in an amount in the range of from about 0.01%
to about 5% by weight of water in the treating fluid.
As mentioned above, the polymer complex fluid loss control
additives which are useful in accordance with the methods of the
present invention are made by polymerizing a cationic, anionic or
amphoteric polymer in the presence of a nonionic host polymer. The
monomers which can be utilized in the polymerization of the
cationic, anionic or amphoteric polymer are those that promote
water solubility including, but not limited to, monomers such as
2-acrylamido-2-methylpropane sulfonic acid,
2-methacrylamido-2-methylpropane sulfonic acid, sulfonated styrene,
vinyl sulfonic acid, allyl ether sulfonic acids such as propane
sulfonic acid allyl ether, methallyl ether phenyl sulfonates,
acrylic acid, methacrylic acid, maleic acid, itaconic acid,
n-acrylamidopropyl-n,n-dimethyl amino acid,
n-methacrylamidopropyl-n,n-dimethyl amino acid,
n-acryloyloxyethyl-n,n-dimethyl amino acid,
n-methacryloyloxyethyl-n,n-dimethyl amino acid,
n-acryloyloxyethyl-n,n-dimethyl amino acid,
n-methacryloyloxyethyl-n,n-dimethyl amino acid, crotonic acid,
acrylamidoglycolic acid, methacrylamidoglycolic acid,
2-acrylamido-2-methylbutanoic acid and
2-methacrylamido-2-methylbutanoic acid. Nonionic monomers which can
be used in the formed (synthesized) polymer include, but are not
limited to, C.sub.1 -C.sub.22 straight or branched chain alkyl or
aryl acrylamide, C.sub.1 -C.sub.22 straight or branched chain
n-alkyl or aryl methacrylamide, acrylamide, methacrylamide,
n-vinylpyrrolidone, vinyl acetate, ethoxylated and propoxylated
acrylate, ethoxylated and propoxylated methacrylate, hydroxy
functional acrylates such as hydroxyethylacrylate and
hydroxypropylacrylate, hydroxy functional methacrylates such as
hydroxyethylmethacrylate and hydroxypropylmethacrylate,
n,n-dimethylacrylamide, n,n-dimethylmethacrylamide, styrene,
styrene derivatives and C.sub.1 -C.sub.22 straight or branched
chain alkyl, aryl or allyl ethers.
The polymer complexes of the present invention are formed by
polymerizing one or more of the above described monomers in the
presence of a nonionic host polymer. The host polymer can be a
synthetic polymer, such as those produced by free radical
polymerization or condensation polymerization or it can be a
natural polymer such as a natural gum, a natural gum derivative, a
starch, a modified starch, a cellulose, a cellulose derivative or
an ethoxylated cellulose derivative. Other polymers that can be
used include, but are not limited to, vinyl polymers, polyolefins,
polyacrylates, polyamides, polyesters, polyurethanes, xanthan gums,
welan gums, succinoglycon, sodium alginates, galactomannans,
carragenan, gum arabic, starch and its derivatives, guar ester
derivatives, silicone containing polymers and their derivatives,
polysiloxanes and their derivatives and proteins and their
derivatives.
The term "interjacent" can be used to describe the polymer
complexes useful in accordance with this invention. By interjacent,
it is meant that the polymers of the polymer complex are
distributed homogeneously throughout the composition and
intermingled to a degree that no visible phase separation will be
observed after standing in the original solution for a long period
of time. On the other hand, a three-dimensional network structure
is also substantially absent (although there may be some
branching), so that a solution manifests only a very minimal
turbidity, if any. As a non-limiting example, an aqueous solution
containing 5 percent by weight of a polymer or interjacent complex
can be prepared and poured through a U.S. Standard Sieve No. 100
(150 .mu.m) and no particles are left on the screen. Alternatively,
a 2.5% by weight solution of the polymer complexes or interjacent
polymer complexes of the present invention will have a turbidity
reading of less than 20 nephelometric turbidity units (NTU's) and
no visible phase separation after standing at ambient conditions
for three months occurs.
Additional information concerning the polymer complex fluid loss
control agents of this invention is disclosed in Provisional
Application Serial No. 60/284,043 entitled Water Soluble Polymer
Complexes filed on Apr. 16, 2001, the disclosure of which is
incorporated herein by reference thereto.
In order to further illustrate the methods of the present
invention, the following examples are given.
EXAMPLE 1
A monomer mixture was prepared containing 0.0043 grams of methylene
bis-acrylamide, 28.27 grams of 2-acrylamido-2-methylpropane
sulfonic acid, 1.79 grams of acrylamide, 4.97 grams of ammonium
chloride, 3.28 grams of N,N-dimethylacrylamide, 0.04 grams of the
tetrasodium salt of ethylenediaminetetraacetic acid, 10.93 grams of
a 50% sodium hydroxide solution, and 0.83 grams of a 50% aqueous
solution of 2-mercaptoethanol. The mixture was added to a
polymerization kettle containing 851.49 grams of deionized water.
The pH of the resulting solution was above 8.5. The mixture was
continuously agitated, heated to 118.degree. F. and 0.67 grams of
2,2'-azobis(2-amidinopropane) hydrochloride initiator was added to
the solution. 66.67 grams of hydroxyethylcellulose having 1.5 moles
of ethylene oxide substitution were added to the agitated solution
and the hydroxyethylcellulose was allowed to undergo complete
hydration therein. A nitrogen sparge in the polymerization kettle
was started and polymerization was allowed to proceed
adiabatically. After a heat rise in the polymerization mixture
stopped, the mixture was heated to 150.degree. F. followed by the
addition of 0.33 grams of 2,2'-azobis(2-amidinopropane)
hydrochloride initiator dissolved in 1.33 grams of deionized water.
The resulting solution was maintained at 150.degree. F. for 30
minutes, allowed to cool and a 10% active solution of the polymer
complex produced was collected.
The polymer complex produced consisted of 1 part by weight of the
synthesized polymer containing 70 mole % of
2-acrylamido-2-methylpropane sulfonic acid, 17 mole % of
N,N-dimethylacrylamide and 13 mole % of acrylamide, and 2 parts by
weight of hydroxyethylcellulose having 1.5 moles of ethylene oxide
substitution. This polymer complex was designated 2004-72.
Following the above described polymerization process, a different
polymer complex was prepared consisting of 1 part by weight of a
synthesized polymer containing 40 mole % of
2-acrylamido-2-methylpropane sulfonic acid, 30 mole % of
acrylamide, 20 mole % of acrylic acid and 10 mole % of
vinylpyrrolidone, and 1 part by weight hydroxyethylcellulose having
1.5 moles of ethylene oxide substitution. This polymer complex was
designated 2004-96.
Following the same polymerization process described above, a
synthesized polymer was prepared without the host polymer, i.e.,
hydroxyethylcellulose with 1.5 moles of ethylene oxide
substitution. The synthesized polymer consisted of 40 mole % of
2-acrylamido-2-methylpropane sulfonic acid, 30 mole % of
acrylamide, 20 mole % of acrylic acid and 10 mole % of
vinylpyrrolidone. This synthetic polymer without the host polymer
was designated 2004-97.
A cement slurry was prepared comprised of Lafarge Class H Portland
cement, 30% of silica flour by weight of cement, 15% of fumed
silica by weight of cement, 1% of a non-dispersing set retarder by
weight of cement, 46.5% water by weight of cement and 2% of a
mixture of foaming and foam stabilizing surfactants by volume of
the water. The non-dispersing set retarder was comprised of a
mixture of lignosulfonate, sugar and sulfonated lignin. The set
retarder is described in detail in U.S. Pat. No. 6,227,294 B1
issued to Chatterji et al. on May 8, 2001, the disclosure of which
is incorporated herein by reference thereto. The mixture of foaming
and foam stabilizing surfactant was comprised of an ethoxylated
alcohol ether sulfate surfactant, an alkyl or alkene
amidopropylbetaine surfactant and an alkyl or alkene
amidopropyldimethylamine oxide surfactant. The density of the
cement slurry was 16.1 pounds per gallon. The three fluid loss
control additives designated as 2004-72, 2004-96 and 2004-97 were
added to separate portions of the above described cement slurry in
the amounts given in Table I below. Thereafter, the test cement
slurried were foamed and then tested for fluid loss in accordance
with the API Specification For Materials And Testing For Well
Cements referred to above using a Multiple Analysis Cement Slurry
Analyzer (MACS). The MACS analyzer includes a sealable chamber
having a known volume where a cement slurry is sheared at high
energy while being pressurized and heated. The test cement slurries
containing the fluid loss control additives were each placed in a
standard 2-liter Waring blender. The weight of each of the cement
slurries was 1,829.84 grams to which was added 10.69 grams of the
mixture of foaming and foam stabilizing surfactants described
above. After mixing in the Waring blender, each of the cement
slurries was separately placed into the MACS chamber. The amount of
each cement slurry utilized was predetermined to result in the
desired foamed slurry density when the slurry was foamed
sufficiently to completely fill the chamber of the MACS analyzer.
After each cement slurry was placed in the MACS chamber, the
chamber was sealed and the paddle inside the analyzer was rotated
at approximately 1,000 RPM for 5 minutes with 1,000 psi nitrogen
pressure applied to the cement slurry. As a result, the cement
slurry in the chamber was converted to a test foamed cement
composition having a density of 12 pounds per gallon. After being
foamed, the test foamed cement composition was subjected to a
temperature schedule which simulates well conditions while
maintaining pressure on the foamed cement composition. After
reaching the maximum temperature equivalent to the bottom hole
circulating temperature (BHCT) of a well, the stirring of the test
foamed cement composition was continued for 1 hour. The test foamed
cement composition was then transferred through a special manifold
system to a special fluid loss cell or to curing cells that were
preheated and charged with nitrogen to the same pressure as the
test foamed cement composition. By venting the nitrogen pressure
from the fluid loss cell or curing cells, the test foamed cement
composition was transferred from the analyzer chamber into the
fluid loss cell or curing cells. When the test foamed cement
composition was transferred to the fluid loss cell, the liquid
effluents from the foamed cement composition were collected to
determine the fluid loss control properties of the test foamed
cement composition. The fluid loss test results are given in Table
I below. In order to determine the stability of the test foamed
cement composition, a portion of the test foamed cement composition
was transferred to the curing cells. The cells were then subjected
to the bottom hole static temperature (BHST) for curing. Upon the
completion of curing, the nitrogen pressure was slowly released
from the curing cells. The set foamed cement composition was then
removed from the cells and tested for compressive strength. The
results of these tests are also given in Table I below.
TABLE I Fluid Loss And Compressive Strength Results Fluid Loss
Quantity of Fluid Loss Foam Compressive Control Additive Control
Additive, % Fluid Loss, cc/30 min Stability at Strength of Foam
Designation by wt. of cement 160.degree. F. 250.degree. F.
275.degree. F. 12 lb/gal After Setting, psi 2004-72 1.0 22 -- --
Stable 1134 2004-72 1.0 .sup. 30.sup.1 -- -- 2004-72 1.5 -- 24 --
2004-72 1.5 -- -- 29 2004-96 1.0 16 -- -- Stable 503 2004-96 1.5 --
28 -- 2004-96 1.5 -- -- 32 2004-97 1.0 116 -- -- Stable 753
From Table I it can be seen that the test foamed cement
compositions containing the polymer complex fluid loss control
additives 2004-72 and 2004-96 exhibited exceptional fluid loss
control in the range of 100-275.degree. F. bottom hole circulating
temperatures (BHCT). The cement composition containing the polymer
2004-97 (without a host polymer) exhibited high fluid loss. All of
the test foamed cement compositions were stable and had good
compressive strengths.
EXAMPLE 2
A portion of the cement slurry designated 2004-72 was foamed in the
MACS Analyzer as described in Example 1 above. The cement slurry
was foamed to a density of 12 pounds per gallon at 80.degree. F.
and 1,000 psi. The temperature of the foamed cement composition was
then gradually raised at a rate of 2.5.degree. F. per minute to
250.degree. F. and held at 250.degree. F. for 1 hour. The foamed
cement composition was then transferred to the curing cells which
were preheated to 250.degree. F. The curing cells were charged with
nitrogen at 1,000 psi. The foamed cement composition in one cell
had a density of 11.77 pounds per gallon and in the other cell
11.76 pounds per gallon before setting. The cells were then cured
at 318.degree. F. and 1,000 psi for 24 hours. The set foamed cement
composition in the curing cells were removed therefrom and cooled
to room temperature at ambient pressure. The set foamed cement
compositions were each cut into 3 sections; top, middle and bottom
and the average densities of the sections were determined. The
results of these tests are given in Table II below.
TABLE II Densities Of Set Samples Cell 1 Density, lb/gal Cell 2
Density, lb/gal Top Middle Bottom Top Middle Bottom 11.77 12.15
12.62 11.65 12.13 12.96
From Table II it can be seen that the average density of the top
section was 11.71 pounds per gallon; the middle section was 12.14
pounds per gallon and the bottom section was 12.79 pounds per
gallon. Thus, the density variation in the cured samples from top
to bottom did not exceed 1 pound per gallon. This result indicates
that the polymer complex fluid loss control additive utilized in
accordance with this invention is non-dispersing.
EXAMPLE 3
Portions of the cement slurries described in Example 1 were foamed
as described in Example 1 to densities of 12 pounds per gallon. The
foamed cement compositions were tested for thickening times in
accordance with the procedures set forth in the API Specification
10 referred to above. The results of the thickening time tests are
set forth in Table III below.
TABLE III Thickening Time Results Quantity of Fluid Loss Fluid Loss
Quantity of Quantity of Quantity of Control Control Silica Flour, %
Fumed Silica, Surfactants, Thickening Additive Additive, % by by
wt. of % by wt. of % by wt. of Temp., Time, Designation wt. of
Cement Cement Cement Water .degree. F. hr:min 2004-72 1.0 35 -- --
250 6:21 2004-72 1.0 30 15 1 250 4:24 2004-96 1.0 35 -- -- 300
6:00+
From Table III it can be seen that the foamed cement compositions
containing the polymer complex fluid loss control additive had good
thickening times.
Thus, the present invention is well adapted to carry out the
objects and attain the ends and advantages mentioned as well as
those inherent therein. While numerous changes may be made by those
skilled in the art, such changes are encompassed within the spirit
of this invention as defined by the appended claims.
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